Disposal of produced water from oil fields is a major concern to oil companies for environmental and economic reasons. One way to dispose off this water is to mix it with injection water. A carbonate reservoir in Saudi Arabia produces wet oil where the salinity of the produced water is high (TDS up to 230,000 mg/L). The produced water contained dissolved gasses (H2S and CO2), and suspended solids (oil, corrosion products). GOSP disposal water has CaCO3 scaling potential. It contains 750 mg/L of H2S. The aquifer water contains 2 mg/L of iron. Iron sulfide scale forms once the disposal water is mixed with the aquifer water. The objective of this study is to assess potential formation damage that can result when the two waters are mixed and injected into the tight carbonate reservoir. The current study included detailed analysis of field waters, determination of scaling potential of various waters, and extensive coreflood testing using reservoir cores. A unique feature of this study is that the cores were examined after the injection of the mixed waters by CT and SEM techniques. Injection of mixed water into reservoir cores created wormholes which increased core permeability. This new finding indicates that disposal water is not always damaging. The effect of iron sulfide particles was found to be a function of the initial core permeability. Iron sulfide particles (0.25 micron) caused damage to cores with permeability < 20 mD after injecting 1,000 PV of the mixed water. No damage was noted in high permeable cores (> 100 mD) even after the injection of 600 PV of the same water. The results of the study identifies various types of scale related to mixing GOSP disposal water and aquifer water, and determine conditions where these waters can be injected. Also, the study highlights an unexpected benefit from injecting H2S containing waters into carbonate reservoirs. Introduction and Background As part of expansion and development program of a field in eastern Saudi Arabia to start production, various water injection scenarios were evaluated. For the first five years of injection, the main source of injection water will be the aquifer water, disposal water, and proposed aquifer-disposal co-mingled waters. However, if aquifer water and the disposal waters can be commingled, assuming no adverse effects on the reservoir performance, a joint pipeline system can be used instead of a segregated system. This can have significant cost avoidance. The formation waters have high TDS (> 200,000 mg/L) and very high H2S content (> 750 mg/L). Aquifer waters contain dissolved iron up to 4–5 mg/L1. Mixing these two waters can precipitate iron sulfide, Equation 1:Equation 1 Iron sulfide can cause formation plugging and injectivity decline2. Filtration of the mixed waters is extremely difficult, particularly in an oily system. Therefore, compatibility studies for these waters are very important. The main objective of this study is to assess the feasibility of mixing aquifer water with disposal waters. Chemical Composition Representative formation water from the field is not available as the field has been mothballed. The chemical compositions of the formation brine from an observation well that was mothballed (Q-47), disposal water from a nearby field-A and aquifer water (Q-859) are given in Table 1. The iron content of aquifer water was 2 mg/L. Q-47 formation water is also not representative of the field. Disposal water from the field-A does not contain significant H2S (Table 1). Since the Field-Q contains about 15 mol% of H2S in the gas phase, (nearby Field-B has about 8 mol% H2S, and measured H2S levels are about 750 mg/L), H2S saturated disposal water was used for evaluating the chemicals and coreflood tests. The sulfide content of this water was measured using Zn-acetate method, and was found to be in the range of 1,200 - 1,300 mg/L. Scaling Potential and Compatibility Studies The OKSCALE program was used to evaluate the scaling potential and saturation indices, and the data are presented in Table 1. Predicted scaling potentials for individual waters and their compatibilities is discussed below.
Oil wells producing from carbonate formations generally experience chemical scaling (carbonates and/or sulfates) during some phase of their production history. In several Saudi Aramco vertical wells, production of formation water containing associated carbon dioxide gas has resulted in calcium carbonate scaling. Scaling potential studies have indicated the threshold level of an organic phosphonate scale inhibitor used to mitigate such scaling in these wells is less than one ppm. This low protection threshold allows considerable leeway in scale squeeze design for the problem wells. Phosphonate based scale inhibitor squeeze treatments provide the most common and effective means of preventing the scale formation in such fields. In vertical well applications, long squeeze lives of more than ten years have been observed in fields producing from carbonates. The residual inhibitor levels have fallen below 0.1 ppm in several of these wells without return of scale. The increased drilling of horizontal holes and inevitable increases in watercut in these wells have led to scale problems. The design of a viable and economic horizontal well scale squeeze treatment was called for. Considerable problems are, however, inherent in the development of such horizontal treatment strategies. Sorbie, et al., recently published a mathematical scale inhibitor squeeze model for use in horizontal well treatments. This model was used to evaluate several treatment options for horizontal wells having a low carbonate scaling potential. Simulated residual returns and squeeze life data were used for different stages and scenarios in Sorbie's model to arrive at the most optimistic squeeze strategy. Based on the information provided by the model and previous vertical well experience, a simple and inexpensive bullheaded squeeze resulted in a successful treatment. This resulted in a substantial economic savings over a coiled-tubing delivered treatment. The theory behind this simple strategy will be discussed. The results of two case studies will be presented.
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